Canadian energy regulators predict Canadians will likely use less fossil fuels in the future, with the baseline case suggesting Canadian fossil fuel use will peak around 2019.
Canada's National Energy Board is an independent federal regulator whose mandate is to
promote safety and security, environmental protection and economic
efficiency in the Canadian public interest, in the regulation of
pipelines, energy development and trade. The Board prepares periodic long-term energy outlooks, which it describes as "the only publically available, long-term energy supply and demand
outlook covering all energy commodities and all provinces and
territories."
On October 26, 2017, the National Energy Board released its latest such report, titled "Canada's Energy Future 2017: Energy Supply and Demand Projections to 2040." The 2017 report uses economic and energy models to explore "how possible energy futures might unfold for Canadians over the long term."
The report features a baseline Reference Case, based on a current economic outlook, a moderate view of energy prices, and
assuming climate and energy policies similar to those announced at the
time of analysis. According to the report, this projection shows Canadian fossil fuel use peaking around 2019, and flattening out in the long term.
The report also considers two alternative scenarios -- a Higher Carbon Price case, and a Technology Case considering increased carbon pricing plus the greater adoption of select emerging
production and consumption energy technologies such as electric vehicles
and solar power. Under these two alternative cases, consumption of fossil fuels would fall 8 and 13% respectively, by 2040.
Energy powers society; society's choices shape energy policy. A blog about our energy resources and the choices they present for society.
ISO New England's 2017 Regional System Plan
The operator of New England's electric grid has issued an updated power system plan, presenting the grid operator's view of power system needs for the next 10 years and how these needs can be addressed. ISO New England, Inc.'s 2017 Regional System Plan portrays the region's energy system as "in the midst of a major evolution
toward
a cleaner, hybrid grid,"
including both traditional resources such as
natural-gas-fired
generation and renewable
technologies such as
wind and
solar,
plus energy efficiency or conservation measures.
ISO New England is the independent system operator for the electric grid serving most of New England. Its tariff as approved by the Federal Energy Regulatory Commission requires it to prepare and periodically update a Regional System Plan, addressing forecasts of annual energy use and peak loads for a 10-year planning horizon, market responses that can meet defined system needs, and descriptions of regional transmission projects that meet identified needs, among other information.
On November 2, ISO New England's board of directors approved its 2017 Regional System Plan (RSP17). The 2017 plan builds on the 2015 plan, while providing updated information on system needs and resources.
Highlights of the 2017 plan include:
ISO New England is the independent system operator for the electric grid serving most of New England. Its tariff as approved by the Federal Energy Regulatory Commission requires it to prepare and periodically update a Regional System Plan, addressing forecasts of annual energy use and peak loads for a 10-year planning horizon, market responses that can meet defined system needs, and descriptions of regional transmission projects that meet identified needs, among other information.
On November 2, ISO New England's board of directors approved its 2017 Regional System Plan (RSP17). The 2017 plan builds on the 2015 plan, while providing updated information on system needs and resources.
Highlights of the 2017 plan include:
- Increased adoption of solar photovoltaic and energy efficiency resources will lead to long-term declines in annual use of electric energy and summer peak demand (but load will grow slightly without more solar PV and efficiency, as was previously predicted).
- The most recent Forward Capacity Market auction (FCA #11), held in February 2017, procured sufficient resources to meet resource adequacy criteria through 2021. These resources include about 264 MW of new generation, plus 640 MW of new demand-side resources (mostly new energy efficiency, with a little new wind and solar).
- The region's portfolio of generating resources is changing. About 4,800 megawatts of generation will be retired from 2010 to summer 2020. Older oil- and coal-fired and nuclear generators are most at risk of retirement due to economic and environmental pressures. Natural-gas-fired and renewable generation like wind and solar are the most likely replacements.
- While the region should have sufficient resources to meet capacity requirements and adequate trans mission facilities to meet reliability criteria, ISO New England says "fuel security remains a primary issue the region must resolve to meet its energy-supply needs. " It cites limited availability of the natural gas transportation infrastructure to supply gas to generating units, and notes the grid operator's ongoing operational fuel-security analysis to quantify the region’s risk.
- Transmission investment (and related costs) continue to grow. From 2002 through June 2017, 730 reliability-oriented transmission projects were put into service in New England states at a cost of $8.4 billion. As of June 2017, another $4 billion in transmission investment for reliability wa s planned. While ISO-NE predicts the overall need for major transmission projects for reliability to decline over the 10-year planning horizon, it says integrating large-scale renewable energy resources is a potential driver for future transmission investments.
Stanford publishes clean energy finance papers
Tuesday, November 7, 2017
Stanford University's Precourt Institute for Energy has launched a Clean Energy Finance Initiative with a forum and the release of a series of papers addressing the challenge and opportunity of dramatically increasing global investment in clean energy deployment.
A framing paper, Derisking Decarbonization: Making Green Energy Investments Blue Chip, presents an investor's view of the risks that could deter significant increases in clean energy investment. It considers the investment required to meet the International Energy Agency's "450 Scenario" aimed at limiting global warming below 2 degrees Centigrade. IEA forecasts that investment in clean energy, must average $2.3 trillion per year through 2040, an annual spending rate roughly three times higher than the rate during the period 2010-2015.
The Stanford framing paper considers a broad range of clean energy technologies, including energy efficiency, renewables, nuclear power, carbon capture and storage (CCS), natural gas, cogeneration, and key enabling technologies including transmission, storage, and demand response. In addition to the practical challenges involved in tripling clean energy investment rates, the paper identifies challenges including the size of clean energy demand relative to annual new investible capital, a mismatch between institutional investor risk profiles and the currently high-risk nature of most clean energy projects, and a locational mismatch between sources of capital and global need for clean energy.
The paper concludes that since most sources of capital will not significantly lower their investment standards for climate reasons, the quality of the green investments offered must be improved: "Green energy projects must become blue chip investments, if we are going to successfully confront climate change." It then analyzes specific issues of investment risk and potential solutions, including market risk, policy risk, project development risk, and investment framework risk.
Eight additional "solutions papers" address specific aspects of investment risk. Some evaluate opportunities to enable more efficient clean energy finance in China or to mitigate financial risk in Indian renewable energy investments. Another examines the implications to investors and to politicians of carbon dividends.
A framing paper, Derisking Decarbonization: Making Green Energy Investments Blue Chip, presents an investor's view of the risks that could deter significant increases in clean energy investment. It considers the investment required to meet the International Energy Agency's "450 Scenario" aimed at limiting global warming below 2 degrees Centigrade. IEA forecasts that investment in clean energy, must average $2.3 trillion per year through 2040, an annual spending rate roughly three times higher than the rate during the period 2010-2015.
The Stanford framing paper considers a broad range of clean energy technologies, including energy efficiency, renewables, nuclear power, carbon capture and storage (CCS), natural gas, cogeneration, and key enabling technologies including transmission, storage, and demand response. In addition to the practical challenges involved in tripling clean energy investment rates, the paper identifies challenges including the size of clean energy demand relative to annual new investible capital, a mismatch between institutional investor risk profiles and the currently high-risk nature of most clean energy projects, and a locational mismatch between sources of capital and global need for clean energy.
The paper concludes that since most sources of capital will not significantly lower their investment standards for climate reasons, the quality of the green investments offered must be improved: "Green energy projects must become blue chip investments, if we are going to successfully confront climate change." It then analyzes specific issues of investment risk and potential solutions, including market risk, policy risk, project development risk, and investment framework risk.
Eight additional "solutions papers" address specific aspects of investment risk. Some evaluate opportunities to enable more efficient clean energy finance in China or to mitigate financial risk in Indian renewable energy investments. Another examines the implications to investors and to politicians of carbon dividends.
FERC report on energy independence executive order
Monday, November 6, 2017
U.S. energy regulators have issued a final report describing actions taken by the Federal Energy Regulatory Commission pursuant to an executive order promoting energy independence and economic growth.
On March 28, 2017, President Trump signed Executive Order 13783, titled Promoting Energy Independence and Economic Growth. Executive Order 13783 includes a variety of directives, generally aimed at reducing federal regulations affecting domestic energy production. Among these mandates is a requirement that all federal agency heads "review all existing regulations, orders, guidance documents, policies, and any other similar agency actions (collectively, agency actions) that potentially burden the development or use of domestically produced energy resources, with particular attention to oil, natural gas, coal, and nuclear energy resources."
On October 31, 2017, the Commission released its final report presenting a review of its actions pursuant to Executive Order 13783. In that report, the Commission identified nine "agency actions that potentially materially burden the development or use of domestic energy resources." The Commission considers agency actions that potentially affect not only oil, natural gas, coal, and nuclear energy resources, but also hydropower and other renewable generation resources.
Of the nine agency actions identified by the Commission as potentially materially burdening the development or use of domestic energy resources, eight relate to the Commission's regulation of hydropower resources. The Commission's final report identified three broad areas where potential material burdens may exist: licensing processes; exemption processes; and determinations on deficient applications. A ninth relates to liquefied natural gas (LNG) proceedings.
The report also describes the Commission's examination of policies regarding centralized electric capacity markets and generator interconnections, and its decision not to identify any potential material burdens regarding these items.
On March 28, 2017, President Trump signed Executive Order 13783, titled Promoting Energy Independence and Economic Growth. Executive Order 13783 includes a variety of directives, generally aimed at reducing federal regulations affecting domestic energy production. Among these mandates is a requirement that all federal agency heads "review all existing regulations, orders, guidance documents, policies, and any other similar agency actions (collectively, agency actions) that potentially burden the development or use of domestically produced energy resources, with particular attention to oil, natural gas, coal, and nuclear energy resources."
On October 31, 2017, the Commission released its final report presenting a review of its actions pursuant to Executive Order 13783. In that report, the Commission identified nine "agency actions that potentially materially burden the development or use of domestic energy resources." The Commission considers agency actions that potentially affect not only oil, natural gas, coal, and nuclear energy resources, but also hydropower and other renewable generation resources.
Of the nine agency actions identified by the Commission as potentially materially burdening the development or use of domestic energy resources, eight relate to the Commission's regulation of hydropower resources. The Commission's final report identified three broad areas where potential material burdens may exist: licensing processes; exemption processes; and determinations on deficient applications. A ninth relates to liquefied natural gas (LNG) proceedings.
The report also describes the Commission's examination of policies regarding centralized electric capacity markets and generator interconnections, and its decision not to identify any potential material burdens regarding these items.
Maine ruling on biomass for renewable energy
Friday, November 3, 2017
Maine renewable energy regulators have issued a ruling clarifying that biomass generators fueled by a "dewatered cellulose pulp" developed by a municipal solid waste recovery company may qualify under the state's renewable portfolio standard. The ruling could help support a municipal waste management company if it creates a market for the company's residual material.
Maine statutes and Maine Public Utilities Commission regulations establish a renewable portfolio standard, or RPS, which currently requires that at least ten percent of the power electricity suppliers sell must come from “new renewable capacity resources” (Class I facilities) and another thirty percent from resources that are renewable or efficient (Class II facilities). The lists of renewable resources eligible for each class are generally similar, although Class I facilities must also be “new" (built, refurbished, etc. after September 1, 2005).
Biomass generators that are fueled by wood, wood waste or landfill gas are eligible for Class I certification or Class II certification depending on their vintage date. Class II certification is also specifically available for anaerobic digestion of agricultural products, by-products or wastes.
In its role as regulator of the renewable portfolio standard, the Public Utilities Commission has had occasion to consider exactly what counts as "biomass," "wood," or "wood waste." In an order adopting amendments to its renewable portfolio standard rule in 2007, the Commission concluded that, “without further legislative direction and in light of the unqualified statutory term ‘biomass,’ the Commission would adopt a relatively broad definition that includes all fuel derived from wood and wood byproducts (along with other organic sources).” In subsequent orders certifying individual facilities as Class I eligible, the Commission has repeatedly reaffirmed this broad interpretation of biomass and has applied it to such fuels as black liquor, biofuel, and pulp and paper fiber sludge.
On September 14, 2017, a company called Fiberight LLC submitted a request to the Commission for an advisory ruling seeking clarification as to whether dewatered cellulose pulp qualifies as an eligible resource pursuant to Maine RPS law. The company's website describes its "Targeted Fuel Extraction (TFE) process to cost effectively and efficiently convert municipal solid waste (MSW) into cellulosic biofuel, plant energy and marketable electricity.... Once renewable fuel production is complete a digestate fiber is available for compost production or can be pelletized for energy recovery." According to its application, Fiberight intends to sell this product to “compliant RPS facilities” and seeks confirmation that the cellulose pulp is consistent with the Commission’s broad definition of biomass.
On October 25, 2017, the Commission issued an order clarifying "that the dewatered cellulose pulp produced by Fiberbright is biomass." The order cites the Commission's consistent employment of "a broad definition of biomass, particularly for organically-derived material," including pulp products. Accordingly, the Commission held that the dewatered cellulose pulp identified by Fiberight is a biomass fuel that Class I or Class II facilities may use to produce Maine RPS eligible electricity.
Maine statutes and Maine Public Utilities Commission regulations establish a renewable portfolio standard, or RPS, which currently requires that at least ten percent of the power electricity suppliers sell must come from “new renewable capacity resources” (Class I facilities) and another thirty percent from resources that are renewable or efficient (Class II facilities). The lists of renewable resources eligible for each class are generally similar, although Class I facilities must also be “new" (built, refurbished, etc. after September 1, 2005).
Biomass generators that are fueled by wood, wood waste or landfill gas are eligible for Class I certification or Class II certification depending on their vintage date. Class II certification is also specifically available for anaerobic digestion of agricultural products, by-products or wastes.
In its role as regulator of the renewable portfolio standard, the Public Utilities Commission has had occasion to consider exactly what counts as "biomass," "wood," or "wood waste." In an order adopting amendments to its renewable portfolio standard rule in 2007, the Commission concluded that, “without further legislative direction and in light of the unqualified statutory term ‘biomass,’ the Commission would adopt a relatively broad definition that includes all fuel derived from wood and wood byproducts (along with other organic sources).” In subsequent orders certifying individual facilities as Class I eligible, the Commission has repeatedly reaffirmed this broad interpretation of biomass and has applied it to such fuels as black liquor, biofuel, and pulp and paper fiber sludge.
On September 14, 2017, a company called Fiberight LLC submitted a request to the Commission for an advisory ruling seeking clarification as to whether dewatered cellulose pulp qualifies as an eligible resource pursuant to Maine RPS law. The company's website describes its "Targeted Fuel Extraction (TFE) process to cost effectively and efficiently convert municipal solid waste (MSW) into cellulosic biofuel, plant energy and marketable electricity.... Once renewable fuel production is complete a digestate fiber is available for compost production or can be pelletized for energy recovery." According to its application, Fiberight intends to sell this product to “compliant RPS facilities” and seeks confirmation that the cellulose pulp is consistent with the Commission’s broad definition of biomass.
On October 25, 2017, the Commission issued an order clarifying "that the dewatered cellulose pulp produced by Fiberbright is biomass." The order cites the Commission's consistent employment of "a broad definition of biomass, particularly for organically-derived material," including pulp products. Accordingly, the Commission held that the dewatered cellulose pulp identified by Fiberight is a biomass fuel that Class I or Class II facilities may use to produce Maine RPS eligible electricity.
NH PUC considers efficiency plan
Thursday, November 2, 2017
New Hampshire utility regulators are considering a three-year statewide energy efficiency plan proposed by several electric and gas utilities. The case could shape the near-term future of New Hampshire energy efficiency programming.
Under a 2016 settlement agreement, the New Hampshire Public Utilities Commission approved the implementation of an Energy Efficiency Resource Standard (EERS) beginning 2018, subject to Commission approval of the specific programs proposed to meet this standard. On September 1, 2017, utilities Liberty Utilities, Public Service Company of New Hampshire, Unitil Energy Systems, Inc. and Northern Utilities, Inc. jointly proposed a 2018-2020 Statewide Energy Efficiency Plan for approval by the Commission. The proposed 2018-2020 New Hampshire Statewide Energy Efficiency Plan document spans 369 pages, and is supported by testimony filed by the utilities.
As described by the utilities, their proposals would extend and expand existing "NHSaves" programs for another 3 years, and would add new initiatives including "a new residential energy audit option, a financing option for moderate income residents, new measure offerings in both residential and commercial programs, and multi -year energy planning to encourage long-term energy savings projects among large commercial customers."
According to the utilities, the measures implemented through the 2018-2020 Plan will save more than 4 billion electric kilowatt-hours and 7.5 million natural gas MMBtu, plus another 5.4 million MMBtus from other fuels, yielding customer energy cost savings of more than $867 million in energy costs over the life of the measures. The utilities also project that the measures "will reduce peak demand by 39 MW, which in tum will reduce costs for all customers."
The Commission has docketed the proceeding as Docket No. DE 17-136, and set a procedural schedule for the case including the filing of testimony and pursuit of possible settlement through November 2017, with hearings on the merits in early December.
Under a 2016 settlement agreement, the New Hampshire Public Utilities Commission approved the implementation of an Energy Efficiency Resource Standard (EERS) beginning 2018, subject to Commission approval of the specific programs proposed to meet this standard. On September 1, 2017, utilities Liberty Utilities, Public Service Company of New Hampshire, Unitil Energy Systems, Inc. and Northern Utilities, Inc. jointly proposed a 2018-2020 Statewide Energy Efficiency Plan for approval by the Commission. The proposed 2018-2020 New Hampshire Statewide Energy Efficiency Plan document spans 369 pages, and is supported by testimony filed by the utilities.
As described by the utilities, their proposals would extend and expand existing "NHSaves" programs for another 3 years, and would add new initiatives including "a new residential energy audit option, a financing option for moderate income residents, new measure offerings in both residential and commercial programs, and multi -year energy planning to encourage long-term energy savings projects among large commercial customers."
According to the utilities, the measures implemented through the 2018-2020 Plan will save more than 4 billion electric kilowatt-hours and 7.5 million natural gas MMBtu, plus another 5.4 million MMBtus from other fuels, yielding customer energy cost savings of more than $867 million in energy costs over the life of the measures. The utilities also project that the measures "will reduce peak demand by 39 MW, which in tum will reduce costs for all customers."
The Commission has docketed the proceeding as Docket No. DE 17-136, and set a procedural schedule for the case including the filing of testimony and pursuit of possible settlement through November 2017, with hearings on the merits in early December.
US announces Gulf oil and gas lease sale
Wednesday, November 1, 2017
The U.S. Department of the Interior has announced plans to auction off the rights to the largest oil and gas lease sale ever held in the United States, covering 76,967,935 acres in federal waters of the Gulf of Mexico, offshore
Texas, Louisiana, Mississippi, Alabama and Florida. The Bureau of Ocean Energy Management's Proposed Lease Sale 250 would be the second offshore sale under the National Outer Continental Shelf Oil and Gas Leasing Program for 2017-2022.
On October 23, Secretary Ryan Zinke announced the proposed region-wide lease sale, offering an area about the size of New Mexico which includes all available unleased areas on the Gulf’s Outer Continental Shelf. According to his announcement, the auction will be held on March 2018. It will cover 14,375 unleased blocks, located from 3 to 230 miles offshore, in water depths ranging from 9 to more than 11,115 feet. The Trump administration stated that it estimates the amount of resources projected to be developed as a result of the proposed region-wide lease sale ranges from 0.21 to 1.12 billion barrels of oil and from 0.55 to 4.42 trillion cubic feet of gas.
According to the Bureau of Ocean Energy Management, the U.S. Outer Continental Shelf contains about 90 billion barrels of undiscovered technically recoverable oil and 327 trillion cubic feet of undiscovered technically recoverable gas; of this, BOEM estimates that the Gulf of Mexico is home to roughly half of these amounts.
On October 23, Secretary Ryan Zinke announced the proposed region-wide lease sale, offering an area about the size of New Mexico which includes all available unleased areas on the Gulf’s Outer Continental Shelf. According to his announcement, the auction will be held on March 2018. It will cover 14,375 unleased blocks, located from 3 to 230 miles offshore, in water depths ranging from 9 to more than 11,115 feet. The Trump administration stated that it estimates the amount of resources projected to be developed as a result of the proposed region-wide lease sale ranges from 0.21 to 1.12 billion barrels of oil and from 0.55 to 4.42 trillion cubic feet of gas.
According to the Bureau of Ocean Energy Management, the U.S. Outer Continental Shelf contains about 90 billion barrels of undiscovered technically recoverable oil and 327 trillion cubic feet of undiscovered technically recoverable gas; of this, BOEM estimates that the Gulf of Mexico is home to roughly half of these amounts.
Subscribe to:
Posts (Atom)
